System and method for monitoring strain &amp; pressure

ABSTRACT

A method for monitoring a well treatment, comprising the steps of installing at least one distributed acoustic strain sensor in at least one monitoring well, said monitoring well being a known distance from the treatment well, initiating a well treatment on the first well, monitoring the formation surrounding the monitoring well using the distributed acoustic strain sensor, and using the distributed acoustic strain sensor, detecting a change in strain at a first location in the monitoring well, using the change in strain to make determinations about the well treatment. The sensor may comprise a fiber optic cable. The change in strain may be used as an indicator that the effect of the well treatment has extended beyond a predetermined preferred treatment zone, the treatment may be a fracture treatment, and the well treatment may be controlled or ceased based on the determinations made in step e).

RELATED APPLICATIONS

The present case claims priority to U.S. provisional application Ser.No. 61/425,603, filed on 21 Dec. 2010, which is incorporated herein byreference in its entirety.

TECHNICAL FIELD OF THE INVENTION

The present disclosure relates generally to a system and a method formeasuring strain and/or pressure in an underground formation.

BACKGROUND OF THE INVENTION

In oilfield operations there is a often need to measure changes information strain or pressure that occur as a result of wellinterventions such as hydraulic fracturing and fluid injection. Theseoperations generally create high pressures in the formation, oftenleading to breakdown (fracturing) of the rock matrix, and will strainthe formation in a volume surrounding the intervention. Measurement ofthis formation strain can be diagnostic of the effectiveness of theintervention and can lead to modification of the intervention parametersthat can give significant economic benefit if the measurement techniqueis inexpensive enough. Changes in strain can occur over time scalesranging from fractions of a second to years and can occur at locationsthat are far away from the well where the intervention takes place(“treatment well”), often affecting rock volumes intersected byneighboring wells. Similarly, detection of abnormal pressure mayindicate fluid paths or potential breakdown or formation/concrete.

Various methods for applying transducers and/or sensors to a cylindricalstructure such as casing and using the sensors or transducers to monitordeformation of the structure as the structure is subjected to variousforces are known. For example, U.S. Pat. No. 7,245,791 discloses thattemperature variations may impart additional strain to an optical fiberand to a supporting structure, such as a well tubular and/or casing,about which the optical fiber is wrapped, and that these temperaturevariations affect the index of refraction in the optical fiber, so thattemperature variations may be considered independently for calibratingthe strain measurements.

Notwithstanding the foregoing, there is currently no in-situ method formeasuring, in a volume around the treatment well and at an acceptablecost and accuracy, formation strain during well interventions. Surfaceand vertical seismic profile (VSP) measurements can be used, but theseare not accurate and require calibration, as they yield formationvelocity as the raw measurement, which in turn needs to be convertedinto strain. In principle, formation strainmeters could be deployed in apermanent installation outside of casing but this can be prohibitivelyexpensive, especially if multiple wells and depth stations are targeted.Furthermore, it is sometimes desirable to detect formation strain and/orpressure in a treatment well, which is difficult if not impossible usingtraditional pressure or strain gauges.

SUMMARY OF THE INVENTION

The present disclosure provides a system and an in-situ permanent methodfor measuring formation strain in a volume around the treatment well andat an acceptable cost and accuracy.

In preferred embodiments, the invention includes installation of DASfibers in both a treatment well and in neighboring wells. Laser lightenters the fiber above the wellhead and a backscattered signal ismeasured by optical components at the surface. Known optical time-domainreflectometry (OTDR) methods and preferably used to infer formationstrain based on the backscattered signal from a segment of the fiberadjacent to the formation. All depths can be interrogated in the timescale of fractions of a millisecond, providing a virtually instantaneousstrain measurement at all depths of interest. Strain/pressureassessments can be performed on many wells at once, providing a samplingof the volume strain or pressure over potentially a large area. Themeasurements can be used to diagnose and correct a geomechanical modelor can be used to directly intervene in the treatment with or withoutintegration with other measurements.

In some embodiments, the invention includes a method for detecting theeffect of a well treatment such as a fracturing treatment or fluidinjection performed in a first well, comprising the steps of: a)installing at least one distributed acoustic strain sensor in at leastone monitoring well that is located a known distance from the firstwell, b) initiating a well treatment on the first well, c) monitoringthe formation surrounding the monitoring well using the distributedacoustic strain sensor, d) using the distributed acoustic strain sensor,detecting a change in strain at a first location in the monitoring well,and e) using the change in strain or pressure detected in step d) tomake determinations about the well treatment in step b). The inventioncan also be used to determine the lateral, horizontal or vertical(formation) extent of the fracture network or induced hydraulicfracture.

The distributed acoustic strain sensors may be installed in one or moremonitoring wells, with each monitoring well between 50 m and 5000 m fromthe first or treatment well. Each distributed acoustic sensor preferablycomprises a fiber optic cable and associated laser interrogator unit forsending and receiving optical signals through the fiber.

The change in strain detected in step d) can be used as an indicationthat the effect of the well treatment has extended to or beyond thelimit of a predetermined preferred treatment zone and the well treatmentmay be controlled or ceased based on the determinations made in step e).The present method can also be used to determine information about theformation between the first well and the monitoring well.

Other embodiments of the invention relate to time-lapse measurement ofeither proximal and/or distal strain or pressure, in a formation before,during, and after production operations. According to the invention,strain measurements can be measured over long periods oftime—seconds/minutes/days/weeks/months/years—giving them greater scopethan normal seismic data.

As used herein, “well treatment” refers to any fluid injection orremoval process that may be carried out on a well, including fraccing,solvent injection, production, and the like.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the preferred embodiments,reference is made to the accompanying drawing, which is a schematicillustration of a system in accordance with a first embodiment of theinvention.

DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

The present disclosure relates generally to a system and a method formonitoring strain or pressure in one or more monitoring wells and usingthe collected information to control processes in a treatment well or tounderstand the effectiveness of those treatments.

In one embodiment, distributed acoustic sensors comprising fiber opticcables such as are known in the art are deployed in one or moremonitoring wells that are located at a distance from the treatment well.The distance between the treatment well and any given monitoring wellmay be in the range of from 50 m to 5000 m. If more than one monitoringwell is used, the wells can be arranged on opposite sides of or evenlyspaced about the treatment well, or the monitoring wells can be locatedin locations determined by the geology and/or topography surrounding thewell. If more than one monitoring well is used, it is possible tocollect more data about the subsurface and therefore to provide moreuseful information.

By way of example only, referring initially to FIG. 1, a treatment well10 and a monitoring well 20 are preferably located according to apredetermined plan. In some embodiments, the treatment well will be onein which a fraccing or other injection operation will be performed.

Treatment well 10 may contain one or more tubulars and may be cased, asshown. In some cases, the well treatment will comprise pumping fluidinto the well at sufficiently high pressure to fracture the adjacentformation, as illustrated by arrows 11, resulting in fractures 13.

One or more fiber optic cables 12 designed to collect distributed strainmeasurements are deployed in monitoring well(s) 20 and coupled to theformation by any suitable means. In the embodiment shown, monitoringwell 20 has been cemented with a fiber optic sensor embedded in thecement. It will be understood that the optic fiber can also be clampedor bonded to a downhole tubular, or acoustically coupled by any othermeans. One or more light boxes 14 containing laser light sources andsignal-receiving means are optically coupled to the fiber at thesurface. The cable may be double-ended, i.e. may be folded back in themiddle so that both ends of the cable are at the source, or it may besingle-ended, with one end at the source and the other end at a pointthat is remote from the source. The length of the cable can range from afew meters to several kilometers, or even hundreds of kilometers. Ineither case, measurements can be based solely on backscattered light, ifthere is a light-receiving means only at the source end of the cable, ora light receiving means can be provided at the second end of the cable,so that the intensity of light at the second end of the fiber opticcable can also be measured.

In some embodiments, the light source may be a long coherence lengthphase-stable laser and is used to transmit direct sequence spreadspectrum encoded light down the fiber. Localized strain or otherdisruptions cause small changes to the fiber, which in turn producechanges in the backscattered light signal. The returning light signalthus contains both information about strain changes and locationinformation indicating where along the fiber they occurred. In someembodiments, the location along the fiber can be determined using spreadspectrum encoding, which uniquely encodes the time of flight along thelength of the fiber.

When it is desired to make measurements, the light source transmits atleast one light pulse into the end of the fiber optic cable and abackscattered signal is received at the signal-receiving means. Knownoptical time-domain reflectometry (OTDR) methods are preferably used toinfer formation strain based on the backscattered signal from one ormore segments of the fiber adjacent to the formation of interest.

Using the present invention, formation strain or pressure can bemeasured in the monitoring well(s) or treatment well(s) over theduration of the treatment process and, if desired, for a period of timethereafter, providing information about changes in the formation strainor pressure over time. Of particular interest are strain measurementsindicating that the effect of the injection in the treatment well hasextended to or beyond the limit of a predetermined preferred treatmentzone. Thus, for example, strain in the formation resulting from theinjection of fluid is preferably detected by fiber optic cable 12 for atleast the duration of the injection. In addition, acoustic eventsattributable strain-induced fractures may also be detectable by fiberoptic cable 12.

Similarly, measurements in a pressurize zone can be used to sensemovement of a pressure front. Pressure in the formation will cause adilation in the matrix, i.e. an isotropic strain in all directions. Afiber oriented in any direction will pick this up as long as is passesthrough a region of changing pressure—the “pressure front.”

All depths can be interrogated in the time scale of fractions of amillisecond, providing a virtually instantaneous strain measurement atall depths of interest. Strain and pressure assessments can be performedon many wells at once, providing a sampling of the volume strain overpotentially a large area. The measurements can be used to diagnose andcorrect a geomechanical model or can be used to directly intervene inthe treatment with or without integration with other measurements. Thus,the present invention allows control of pressures to reduce out-of-zoneeffects and also allows better understanding of production given themeasured connectivity.

In addition to the foregoing, it has been observed that strain anomaliestypically travel from the treatment well to neighboring wells and that,shortly after the strain anomaly reaches a neighboring well, it travelsup and down that wellbore, creating pressure connectivity over asignificant vertical column (as measured using pressure gauges in thefield data). This is undesirable for optimal production of the zones.The present invention makes it possible to monitor the treatment usingDAS signals in the monitoring wells and to stop pumping when initialinter-well connectivity is established.

The present methods have no inherent lower limit to the frequency ofinvestigation and are therefore limited only by the stability of thehardware over long time scales. There are various methods of backscattermeasurement, including the use of Rayleigh and Brillouin backscattering,and one method may be preferred over others for this implementation ofthe present invention, especially at low frequency.

The particular embodiments disclosed above are illustrative only, as thepresent claimed subject matter may be modified and practiced indifferent but equivalent manners apparent to those skilled in the arthaving the benefit of the teachings herein. Furthermore, no limitationsare intended to the details of construction or design herein shown,other than as described in the claims below. It is therefore evidentthat the particular illustrative embodiments disclosed above may bealtered or modified and all such variations are considered within thescope and spirit of the present claimed subject matter. By way ofexample only, one of skill in the art will recognize that the number andlocation of the monitoring well(s) with respect to the first well, thenumber and configuration of cables and sensors, the sampling rate andfrequencies of light used, and the nature of the cable, couplingdevices, light sources, light signals, and photodetectors can all bemodified within the scope of the invention. By way of further example,embodiments have been described in which a fiber is placed in one ormore wells that are spaced apart from the treatment well. It will beunderstood that fibers could also be placed in the treatment wellitself. Moreover, it will be appreciated that such a development effortmight be complex and time-consuming, but would nevertheless be a routineundertaking for those of ordinary skill in the art having the benefit ofthe present disclosure.

The subject matter of the present disclosure is described withspecificity. However, the description itself is not intended to limitthe scope of the claimed subject matter. The claimed subject matter,thus, might also be embodied in other ways to include different steps orcombinations of steps similar to the ones described herein, inconjunction with other present or future technologies. Moreover,although the term “step” may be used herein to connote different methodsemployed, the term should not be interpreted as implying any particularorder among or between various steps herein disclosed except when theorder of individual steps is explicitly described.

For illustrative purposes only, two examples of implementation of theinventive concepts are set forth below.

Example 1 Hydraulic Fracturing

According to a first exemplary embodiment, distributed OTDR sensing canbe used to detect hydraulic fracturing according to the followingworkflow:

-   -   deploy one or more DAS fibers in one or more wells in the        vicinity of an intended hydraulic fracturing operation;    -   prior to hydraulic fracturing in the area, record noise levels        along the fiber as a control measurement;    -   upon initiation of pumping of fracture fluids, for any or all        fracture stages and fluid types, including mini-frac (or test        frac), record the strain field as measured by the DAS system,        for all locations in the well where the formation can be        affected by the fracture operation;    -   simulate the strain field as a function of time and space using        a geomechanical simulation;    -   from the results of the simulation, make a prediction of the        axial strain measurements at the places where the DAS fibers        have made the measurements;    -   compare the predictions and measurements and adjust the        geomechanical model parameters to minimize the difference;    -   use the new geomechanical model to make further predictions that        can be compared with DAS (or other) measurements;    -   use the new geomechanical model to optimize perforation        locations and pumping schedule (and any other relevant        parameters) such that the predictions of the updated model, with        the new perforation locations and pumping schedule, predict        optimal production over the life of the field; and    -   keep the geomechanical model evergreen by including data from        either infill hydraulic fracturing, recompletion fractures,        long-term depletion or other changes in formation strain due to        production operations.

The foregoing workflow can be generalized beyond hydraulic fracturedetection to include any earth motion that can be measured with DAS,including but not limited to pressure or radial strain.

Example 2 Depletion

According to a second exemplary embodiment, the inventive methods areused to measure time-dependent strain in a depleting field. Morespecifically, the inventive methods provide a way to measure moderateresolution differential depletion in a reservoir. The cost andavailability of fiber optic sensors, allows construction of an arealpicture of depletion induced strain.

Thus, according to this embodiment, distributed OTDR sensing can be usedto detect and monitor field depletion according to the followingworkflow:

-   -   deploy one or more DAS fibers in one or more wells in the        vicinity of an intended hydraulic fracturing operation;    -   prior to field startup, record noise levels along the fibers as        a control measurement;    -   upon initiation of field depletion, the strain field as measured        by the DAS system, for all instrumented wells;    -   simulate the strain field as a function of time and space using        a geomechanical simulation;    -   from the results of the simulation, make a prediction of the        axial strain measurements at the places where the DAS fibers        have made the measurements;    -   compare the predictions and measurements and adjust the        geomechanical model parameters to minimize the difference        therebetween;    -   make changes in the model as required to match the data        highlight differences in subsidence/depletion for different        parts of a formation, leading to localized interventions;    -   alternatively, depleted/depleting areas may be obvious even        without the benefit of a geomechanical model as areas with        greater or lesser strain changes;    -   if the fiber is also configured to measure formation pressure, a        measure of rock compressibility might be possible from strain        and pressure.

While the invention has the particular advantaged described above, itcan be used advantageously to detect inter-well effects caused by othersources and can be used to determine information about properties of theformation between wells. Accordingly, the protection sought herein is asset forth in the claims below.

1. A method for detecting the effect of a well treatment performed in afirst well, comprising the steps of: a) installing at least onedistributed acoustic strain sensor in at least one monitoring well, saidmonitoring well being a known distance from the first well; b)initiating a well treatment on the first well; c) monitoring theformation surrounding the monitoring well using the distributed acousticstrain sensor; d) using the distributed acoustic strain sensor,detecting a change in strain or pressure at a first location in themonitoring well; and e) using the change in strain detected in step d)to make determinations about the well treatment in step b).
 2. Themethod according to claim 1 wherein distributed acoustic strain sensorsare installed in at least two monitoring wells.
 3. The method accordingto claim 1 wherein each monitoring well is between 50 m and 5000 m fromthe first well.
 4. The method according to claim 1 wherein thedistributed acoustic sensor comprises a fiber optic cable.
 5. The methodaccording to claim 1 wherein the change in strain detected in step d)indicates that the effect of the well treatment has extended to orbeyond the limit of a predetermined preferred treatment zone.
 6. Themethod according to claim 1 wherein the well treatment is a fracturetreatment.
 7. The method according to claim 1 further including the stepof controlling the well treatment based on the determinations made instep e).
 8. The method according to claim 1, further including the stepof ceasing the well treatment based on the determinations made in stepe).
 9. The method according to claim 1 further including the step ofdetecting, at one or more locations that are vertically spaced from thefirst locations, further changes in strain that are related to thechange in strain detected in step d).
 10. The method according to claim8 further including the step of using the change in strain detected instep d) to determine information about the formation between the firstwell and the monitoring well.